The present invention relates to a method of recovering crude oil and natural gas using a heater/treater/separator with a novel gas lifting and liquid injection system. The invention further relates to recovery systems that may be integrated in a single component. The invention further relates to oil and gas production systems with reduced environmental impact based on utilization of naturally occurring energy and other forces in the well and the process. The invention further relates to compressors controlled by naturally occurring gas from the well. The invention further relates to the prevention of decreased flow from a well due to corrosion, viscosity buildup, etc. downhole. The invention further relates to more cost-effective oil and gas production systems that costs less to purchase, maintain, and operate.
Oil and gas recovery from subterranean formations has been done in a number of ways. Some wells initially have sufficient pressure that the oil is forced to the surface without assistance as soon as the well is drilled and completed. Some wells employ pumps to bring the oil to the surface. However, even in wells with sufficient pressure initially, the pressure may decrease as the well gets older. When the pressure diminishes to a point where the remaining oil is less valuable than the cost of bringing it to the surface using secondary recovery methods, production costs exceed profitability and the remaining oil is not brought to the surface. Thus, decreasing the cost of secondary recovery means for oil from subterranean formations is especially important for at least two reasons:
(1) Reduced costs increases profitability, and
(2) Reduced costs increases production.
Many forms of secondary recovery means are available. The present invention utilizes gas lift technology, which is normally expensive to install, operate and maintain, and often dangerous to the environment. Basically, gas lift technology uses a compressor to compress the lifting gas to a pressure that is sufficiently high to lift oil and water (liquids) from the subterranean formation to the surface, and an injection means that injects the compressed gas into a well to a depth beneath the surface of the subterranean oil reservoir.
Since the 1960""s gas lift compressors have used automatic shutter controls to restrict air flow through their coolers. Some even had bypasses around the cooler, and in earlier models some didn""t even have a cooler. Water wells employing free lift do not cool the compressed air used to lift the water to the surface. Temperature control at this point has never been considered important other than to prevent the formation of hydrates from the cooling effect of the expanding lift gas. Therefore, most lifting has been performed with gas straight from the compressor. The heat of compression in this gas is not utilized effectively and is rapidly dissipated when the lift gas in injected into a well.
Compressors for this service are expensive, dangerous, require numerous safety devices, and still may pollute the environment. Reciprocating compressors are normally used to achieve the pressure range needed for gas lifting technology. Existing reciprocating compressors are either directly driven by a power source, or indirectly driven via a hydraulic fluid. While both are suitable for compressing lifting gas, most prior art reciprocating compressors are costly to operate and maintain. Moreover, existing reciprocating compressors are limited to compressing gases because they are not designed to pump both gas and liquids simultaneously and continuously.
Existing compressors use many different forms of speed and volume control. Direct drive and belt drive compressors use cylinder valve unloaders, clearance pockets, and rpm adjustments to control the volume of lift gas they pump. While these serve the purpose intended, they are expensive and use power inefficiently compared to the present invention. Some prior art compressors use a system of by-passing fluid to the cylinders to reduce the volume compressed. This works, but it is inefficient compared to the present invention.
Another example of wasted energy and increased costs and maintenance is in the way the compressing cylinders are cooled in prior art compressors. All existing reciprocating compressors use either air or liquid cooling to dissipate the heat that naturally occurs when a gas is compressed. The fans and pumps in these cooling systems increase initial costs, and require energy, cleaning, and other maintenance. Prior art reciprocating compressors also require interstage gas cooling equipment and equipment on line before each cylinder to scrub out liquids before compressing the gas.
Another example of the inefficiency of prior art technology relates to current means for separating recovery components. Existing methods employ separators to separate primary components, then heater treaters to break down the emulsions. In some cases additional equipment is required to further separate the fluids produced. In each case, controls, valves, burners and accessories add to the cost, environmental impact and maintenance of the equipment.
Prior art teaches injecting hot gas to try to create counter flowing temperatures. However, the hot gas upsets the natural state of the fluids in the well and its low density provides poor heating of the well piping where downhole buildup may interfere with fluid flow to the surface.
Thus, another problem plaguing current technology is downhole buildup of paraffin and other impediments to the smooth and continuous flow of oil to the well surface.
Hot gases work in thinning the fluids, but tend to cause corrosion of the well tubing and casing. Hot gases can also create chemical problems by causing the lighter hydrocarbons to flash out of the fluids downhole, making them more viscous as they cool. Steam works to a degree, but has similar problems with those caused by other hot gases, requires excessive caloric input, and adds water to the oil in the subterranean formation.
A superior method of combatting downhole buildup of paraffin and other impediments employs the injection of hot oil or salt water to dilute the viscous fluids in the well. Hot oil works well, but until now was too costly to use without interrupting production. The usual method utilizing hot oil or hot salt water requires that the well be shut down, then oil or salt water is injected by a pumping unit immediately after heating it with a heating unit. This technology, which uses a truck/tank trailer with burners to heat the oil and pumps not only interrupts production, but is costly and dangerous.
The present invention is referred to herein as the xe2x80x9cBackwash Production Unitxe2x80x9d or xe2x80x9cBPUxe2x80x9d. In its broadest aspect the BPU provides a process and apparatus for recovering crude oil and natural gas from a subterranean formation through a well in fluid communication therewith. The method includes conducting natural gas up through the well to the surface, compressing a portion of the gas, capturing heat from the compressed gas, injecting cooled compressed gas into the well to a sufficient depth that it mixes with crude oil downhole in the well, using the compressed gas to lift crude oil up through the well to the surface, separating the components recovered at the well surface and distributing them for well maintenance or for sale or storage, and repeating the process by compressing natural gas from the well.
The BPU is particularly attractive for enhancing production of crude oil in that the compressor and pumping rates are controlled by wellhead pressure. In particular, the greater the wellhead pressure, the faster the BPU compresses and pumps. If the wellhead pressure falls to zero or a preset limit, the compressor and pumping stop.
The BPU is also particularly attractive for cost-effective production because it greatly reduces the cost of compressing the lifting gas and separating the components produced by the well. This is achieved by simplifying the design and by utilizing energy from the other components of the system that would otherwise be wasted in prior art compressors. Where the prior art uses gas compressors and pumps, the BPU cylinders pump both gas and liquids simultaneously. Where prior art compressors require coolers and fans, the BPU dissipates the heat of compression by using it in separating the fluids from the subterranean formation and to heat liquids for well maintenance. Where the prior art uses special control and accessories to control volume, and pumping and compression speed, the BPU uses the wellhead pressure to control these rates. Where the prior art requires scrubbers to prevent fluids from entering the compression cylinders, the BPU compressors function normally with fluids present. Where the prior art continues to use the same energy when production falls, the BPU automatically adjusts its compression and pumping rates to match the lower level of recovery.
In addition, the BPU eliminates sealing packing and has substantially fewer moving parts than prior art technology. This reduces the danger of operating the recovery system and further reduces initial costs, and the costs of maintenance and energy for operation. The BPU also has no pumps for cooling or lubricating, and no sealing packing, thereby further enhancing its cost-effectiveness in recovering natural gas and crude oil.
In addition, the separately mounted power source for the BPU requires less maintenance and downtime.
Another aspect of the BPU is that it has the capability of safely and efficiently heating oil and salt water and then injecting the hot fluid into the well without interrupting production.
A particularly attractive feature of the BPU for enhancing production of crude oil is that hot oil and/or water may be injected into the well simultaneously, without interfering with the injection of the cooled compressed gas and the recovery of the crude oil and natural gas. This is achieved by using valving that permits the BPU to heat and inject liquids into the well to treat downhole problems that may inhibit production. Additional valving permits the injection of additional chemicals where corrosion or extreme paraffin buildup is a problem. Additional heating or cooling may be achieved with an internal tube in the BPU which acts as a heat exchanger.
This feature of the BPU is achieved by injecting the cooled lift gas down the center of the well injection string while injecting hot oil down the side coating of the pipe. Thus, the BPU greatly improves prior art methods of combatting downhole buildup of paraffin and other impediments to the smooth and continuous flow of oil to the well surface.
Still further, the BPU is particularly attractive as an environmentally safer means of recovering crude oil and natural gas from subterranean formations. Since the BPU has no fans, external coolers, heaters, scrubbers, burners, unloaders, volume controls or compressor lubricating devices, none of these components can fail and cause environmental damage.
Another extremely attractive aspect of the BPU is that it can be safely installed at the wellhead. Shorter piping requirements, reduced pressure differentials, the lack of danger from burners, and the reduced danger from electrical sparks all contribute to the safety of the BPU.